1. Field of the Invention
The burning of fossil fuels, for example in a utility power plant boiler, produces combustion effluents that include undesirable sulfur and nitrogen compounds, primarily nitric oxide (NO) and sulfur dioxide (SO.sub.2). Combustion processes are known to produce other environmental contaminants such as unburned hydrocarbons and carbon monoxide which are also released in the flue gas in various concentrations. The nitric oxide is oxidized in the atmosphere to nitrogen dioxide, which subsequently reacts with hydrocarbons in the presence of sunlight to form photochemical "smog". Prior research has shown that emissions of sulfur dioxide into the atmosphere can combine with rainwater to produce acidic deposition or "acid rain" which damages lakes, streams, fish populations and forest preserves. Recent environmental research, particularly in West Germany, concerning atmospheric transport, chemistry and deposition associated with "acid rain" suggests that substantial forest damage is also caused by nitrogen oxides. Prior human health effects research in Tennessee has been cited by the U.S. EPA as justification for emission standards to control nitrogen oxides produced by combustion processes.
Combustion products from automotive internal combustion engines, fossil fuel power plants, process furnaces, incinerators and the like all contribute to the production of nitric oxide. Control of nitric oxide production has been directed toward modifications in the combustion process or removal of the nitric oxide from the combustion products prior to discharge into the atmosphere. Examples of these control measures were discussed at the EPA/EPRI Joint Symposia on stationary combustion NO.sub.x control held in Dallas, Tex. in 1983 and Boston, Mass. in May, 1985.
There have been numerous efforts to effectively remove nitric oxide from combustion effluents. One of the major difficulties has been that many of these devices only operate well with relatively large oxygen excess. This is true of power plant boilers, process furnaces, gas turbines, diesels, stratified charge engines, and spark ignition engines with thermal reactors. These devices generally contain flue gases with oxygen concentrations from 0.1 to 10 volume percent and nitric oxide concentrations from 100 to 4000 ppm. Thus, oxygen is present in large excess with respect to nitric oxide. While it is well known how to reduce both nitric oxide and oxygen with large quantities of a reducing agent, desirably, a process should reduce nitric oxide selectively.
Effluents from the combustion processes named previously may contain substantial concentrations of sulfur dioxide in proportion to the sulfur in the fuel. Since coal is an economically attractive fuel in the U.S. for large fuel consumers including electrical utility boilers, there have been numerous processes developed to control sulfur emissions including wet scrubbers, spray dryers, fluidized bed combustor, and in-furnace sorbent injection processes (also known as LIMB). One of the most prevalent methods of removing SO.sub.2 from combustion effluents has been the wet scrubber. However, utilities have expressed disappointment with wet scrubbers in terms of power consumption, capital cost, frequent failures, corrosion, etc. A dry SO.sub.2 removal process is frequently preferred where the spent sulfur capture material can be collected and removed along with the fly ash. Fluidized bed combustion systems show promise as an alternative for new power plants, but retrofit applications are very costly. Current research and development efforts for retrofit applications have been directed at in-furnace sorbent injection processes leading to dry SO.sub.2 removal as discussed at the recent EPRI/EPA First Joint Symposium on Dry SO.sub.2 Control Technologies in San Diego, Calif. in November, 1984.
One of the primary limitations of most current NO.sub.x and SO.sub.x control technologies is that they require separate costly equipment and process control measures that occasionally degrade plant performance and reliability. Therefore, there is an important need for a simultaneous NO.sub.x and SO.sub.x control technology that utilizes only one set of equipment and preferably is a dry process that requires little or no equipment in direct contact with the combustion effluent stream.
Efforts have been made to avoid the problems of wet scrubbing SO.sub.2 control systems wherein the gas contacts a finely divided SO.sub.2 sorbent material that has been dried to a powder by the heat of the flue gas stream. These systems have posed some problems, but importantly, the commonly used sorbent materials have no ability to also reduce NO.sub.x emissions. Therefore, a separate NO.sub.x control system is required. Fluidized bed systems have been developed for SO.sub.2 control, but desulfurization efficiency is low if the bed is operated at temperatures to minimize NO.sub.x emissions and their NO.sub.x control efficiency is poor when optimized for cost effective sulfur capture. In addition, development problems exist with heat removal from the bed without coolant tube burnout. Also, most systems require the spent reactants to be regenerated or subject to conversion treatment to obtain useable by-products. For these reasons, utility and environmental research organizations have expressed a need for simultaneously removing NO.sub.x and SO.sub.x from a combustion effluent stream with a dry process that can be retrofit to an existing boiler without requiring major lower furnace modifications with a fluid bed or large space consuming wet scrubbers at the stack. It is also preferable to have a dry spent reactant material that can be collected by a conventional existing precipitator or baghouse.